The purpose of oil reservoir characterization is to provide a detailed description of the rock, pore space, and fluid system so that the behavior of the reservoir either under production or during water injection can be understood and modeled over the life of the reservoir. Pyrolysis methods that have been developed to assess reservoir characteristics are disclosed in U.S. Pat. Nos. 5,866,814 and 6,823,298, the disclosures of which are incorporated herein by reference. These methods are based on assessing the residual hydrocarbon staining that is found on samples from oil reservoirs obtained during either drilling or coring operations. When assessing movable hydrocarbons, (i.e., oil), the residual hydrocarbons that are analyzed represent only a fraction of those that are present in a bulk sample under reservoir conditions. These “moveable” hydrocarbons are lost during the drilling process via flushing with mud filtrate and through volatilization when the samples are brought from reservoir to atmospheric conditions. Nonetheless, the characteristics of the residual “moveable” hydrocarbons are well preserved and well understood in relation to reservoir performance and can be exploited successfully by the prior methods.
Residual hydrocarbons from “immoveable” hydrocarbons are present in rock samples in roughly the same proportional quantity in the reservoir. Some losses may occur during storage and exposure to air, but these losses are relatively minor. In an oil reservoir, the “immoveable” hydrocarbons of most concern are tar (solid material that is similar to the asphaltene component in crude oil and soluble in organic solvents) and pyrobitumen (insoluble tar, originally derived from tar). These two materials are the primary substances that lead to a reduction in the ability to move fluids (either oil or water) in a reservoir. Therefore, the ability to quantify these materials in terms of their volume, and in relation to reservoir porosity, provides a means to assess their effect on reservoir performance that has been difficult to attain through the prior art methods available to the industry.
For example, a frequently utilized method of assessing hydrocarbon saturation in a reservoir is via the Archie Equation, which utilizes reservoir parameters such as the cementation and saturation exponents in the calculation. These factors are sensitive to changes in lithology or facies within a reservoir. However, these parameters are also sensitive to the wettability of the reservoir, which typically changes drastically when encountering a zone with a substantial quantity of tar. Thus, the calculation of the hydrocarbon saturation in a reservoir is compromised if the composition of that material is variable. Furthermore, the Archie Equation does not discriminate between oil, tar and pyrobitumen.
Another means of assessing oil reservoir fluid properties are NMR logging tools. These tools provide very useful information regarding the nature of reservoir fluid, whether it is light oil, medium oil, heavy oil or tar. However, the available analytic apparatus and methods do not include a means for the explicit calculation of the volumes of these components, and, like all petrophysical logging tools, rely on interpretations based on indirect measurements and assumptions.